1. The Field of the Invention
The present invention relates to a method and system of determining gas content, dewatering time, critical desorption pressure, and/or other reservoir and operational variables, referred to as production factors, for coalbed natural gas wells. The present invention also relates to determining these production factors for other carbonaceous material reservoir wells including carbonaceous shale, shales, tight sands, and muddy sands or other methane reservoirs wherein the methane is at least partially dissolved in water within the reservoir. In particular, this invention relates to a method and system for measuring a partial pressure of methane or a predictor substance for a coalbed natural gas reservoir and determining production factors therefrom.
2. The Relevant Technology
With reference to FIG. 1, a typical completed coalbed natural gas well includes a borehole which is drilled to at least a depth of a coal seam. During drilling and completion of the well an initial borehole is drilled to or through one or more coal seams and a casing is set to at least the top of the lowest coal seam. Each coal seam of interest is then accessed from the wellbore either by perforating holes from the wellbore into the coal seam, or by open hole completion of the wellbore at the lowest coal seam. In many cases the wellbore contains water which originates from one or more layers of the geological strata, including some coal seams, through which the borehole is drilled, or that may be residual from the drilling and completion process. In many instances the coal seams of interest are wet which means that the coal contains water in at least some portion of the coal seam. In some cases the coal seams can be dry or partially dry which means that the coal seam has no or limited amounts of water. In some cases, coal seams are stimulated or otherwise treated using techniques such as fracturing, acid treatment, recirculation of water, and other known methods.
Typically, production of methane is initiated by pumping fluid from the well to reduce the pressure on the coal seam. This fluid typically contains dissolved methane, termed “solution gas.” When the overall hydrostatic pressure of the well at the depth of the coal seam is lowered to the critical desorption pressure of the methane contained within the coal seam, further reductions in pressure lead to off-gassing of methane. At this point the well is considered to be in production. When a well is pre-production, the primary fluid flow through the reservoir is condensed phase, typically water. When a well is in production, both gas and condensed phase fluid flow through the reservoir, typically in competition. Gas flow is due to expansion of the gas after it devolves from the coal. Condensed phase fluid flow is due to continued pumping of that fluid from the wellbore throughout most of the life of the well. In some cases, for wells that have been substantially dewatered and that have little or no hydrostatic pressure remaining, reduced pressure systems, e.g. vacuums, may be installed to further reduce the reservoir pressure and devolve and produce further gas.
Depending upon the reservoir conditions and the coal type, formations, depth and other geological characteristics, fluid from a well may need to be pumped for a very short time (e.g. not at all, if overpressurized with gas) or for a very long time (e.g. up to four years or longer for severely gas undersaturated or low permeability coals) in order to reach production. The life of the well during which it produces economical amounts of methane, and the amount of gas that is produced during that time, also varies depending on the amount of methane entrained, contained, adsorbed or otherwise present in the coal bed. In certain circumstances the life of a well may be up to 30 years or longer.
Traditionally, coal bed methane production factors have been determined by a variety of methods. One known method of determining the critical pressure which the well must reach in order to produce methane by off-gassing involves retrieval of a core sample of the coal, transportation of the core sample to a laboratory setting, and quantification of the amount of methane contained within the sample coal via gas desorption. As seen in FIG. 2, this quantity is then analyzed to determine the coal gas content and compared to an adsorption isotherm of the same or a similar coal in order to determine the critical desorption pressure of the coalbed reservoir. The isotherm of the coal or coal gas content curve represents the amount of methane the coal may contain depending upon the pressure. More particularly, the sample of the coal from the reservoir itself is subjected to reduced pressure over time to measure the amount of methane which it contained. To this measurement is added a “lost gas” estimation to account for gas that issued from the coal sample during retrieval. The total amount of methane is then plotted on the isotherm chart and a correlation is made to the ideal curve. Where the saturation gas curve and measured gas content intersect is the critical pressure which must be reached by pumping in order for the well to produce methane. Other factors may be deduced from this plot or map. Unfortunately, this process is expensive, time consuming, and error-prone.